U.S. patent application number 16/327733 was filed with the patent office on 2020-04-02 for hybrid axial and radial receiver configurations for electromagnetic ranging systems.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Akram Ahmadi Kalateh Ahmed, Ilker R. Capoglu, Burkay Donderici.
Application Number | 20200102818 16/327733 |
Document ID | / |
Family ID | 62978666 |
Filed Date | 2020-04-02 |
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United States Patent
Application |
20200102818 |
Kind Code |
A1 |
Ahmed; Akram Ahmadi Kalateh ;
et al. |
April 2, 2020 |
Hybrid Axial and Radial Receiver Configurations for Electromagnetic
Ranging Systems
Abstract
Systems and methods for active ranging-while-drilling (ARWD) for
collision avoidance and/or well interception. A method for
electromagnetic ranging of a target wellbore may comprise disposing
a downhole measurement tool into a wellbore, wherein the downhole
measurement tool may comprise receivers comprising at least one
radially spaced pair of the receivers and at least one axially
spaced pair of the receivers; performing field measurements with
the receivers, where a first set of field measurements are from at
least one radially spaced pair of the receivers, and a second set
of field measurements are from at least one axially spaced pair of
the receivers; and calculating at least one target well parameter
of a target well from at least one of the first set of field
measurements and the second set of field measurements.
Inventors: |
Ahmed; Akram Ahmadi Kalateh;
(Bedford, MA) ; Capoglu; Ilker R.; (Houston,
TX) ; Donderici; Burkay; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
62978666 |
Appl. No.: |
16/327733 |
Filed: |
January 27, 2017 |
PCT Filed: |
January 27, 2017 |
PCT NO: |
PCT/US2017/015392 |
371 Date: |
February 22, 2019 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
G01V 3/18 20130101; G01V
3/34 20130101; E21B 47/0228 20200501; E21B 47/092 20200501; G01V
3/30 20130101 |
International
Class: |
E21B 47/022 20060101
E21B047/022; G01V 3/30 20060101 G01V003/30; G01V 3/34 20060101
G01V003/34; E21B 47/09 20060101 E21B047/09 |
Claims
1. A method for electromagnetic ranging of a target wellbore,
comprising: disposing a downhole measurement tool into a wellbore,
wherein the downhole measurement tool comprises receivers
comprising at least one radially spaced pair of the receivers and
at least one axially spaced pair of the receivers; performing field
measurements with the receivers, where a first set of field
measurements are from at least one radially spaced pair of the
receivers, and a second set of field measurements are from at least
one axially spaced pair of the receivers; and calculating at least
one target well parameter of a target well from at least one of the
first set of field measurements and the second set of field
measurements.
2. The method of claim 1, further comprising calculating at least
one first target well parameter based, at least partially, on the
first set of field measurements; and calculating at least one
second target well parameter based, at least partially, on the
second set of field measurements.
3. The method of claim 2, wherein the at least one first target
well parameter is calculated based on the first set of field
measurements; and the at least one second target well parameter is
based on the second set of field measurements.
4. The method of claim 2, wherein the calculating at least one
target well parameter uses a weighted combination of the at least
one first target well parameter and the at least one second target
well parameter.
5. The method of claim 4, further comprising determining weights
for the weighted combination based on the at least one second
target well parameter.
6. The method of claim 5, further comprising determining a
threshold based on a distance or relative angle between the
wellbore and the target wellbore.
7. The method of claim 4, wherein the weighted combination assigns
a value of 0 or 1 to a first weight for the at least one first
target well parameter and a value of 0 or 1 to a second weight for
the at least one second target well parameter.
8. The method of claim 1, wherein the at least one radially spaced
pair of the receivers comprise a first pair of radially spaced
receivers positioned on the downhole measurement tool at a
substantially same axial position and a second pair of radially
spaced receivers positioned on the downhole measurement tool at a
different azimuthal position than the first pair.
9. The method of claim 1, wherein at least one receiver of the
radially spaced pair of the receivers is shared with the axially
spaced pair of the receivers.
10. The method of claim 1, wherein at least one receiver of the at
least one radially spaced pair or the axially spaced pair is
oriented in a direction perpendicular to a longitudinal axis of the
downhole measurement tool.
11. The method of claim 1, wherein the calculating at least one
target well parameter of a target well comprises applying an
inversion technique to the second set of field measurements to
provide a first calculated distance and a first calculated
inclination angle to the target well.
12. The method of claim 11, wherein the calculating at least one
target well parameter of a target well further comprises, applying
a gradient technique to the first set of field measurements to
determine a second calculated distance and a second calculated
inclination angle to the target well if the first calculated
distance and the first calculated inclination angle to the target
well are less than respective thresholds.
13. The method of claim 1, further comprising determining
deviations in path of the wellbore based, at least in part, on the
at least one target well parameter, correcting a trajectory of a
bottom hole assembly trajectory used in drilling the wellbore
based, at least in part, on the determined deviations; and
continuing drilling the wellbore with the bottom hole assembly.
14. An electromagnetic ranging system comprising: at least one
radially spaced pair of receivers; at least one axially spaced pair
of receivers; and an information handling system, wherein the
information handling system is configured to switch between the at
least one radially spaced pair of receivers and the at least one
axially spaced pair of receivers.
15. The electromagnetic ranging system of claim 14, wherein the
information handling system is operable to calculate at least one
target well parameter of a target well from at least one of first
field measurements for the at least one radially spaced pair of
receivers or second field measurements for the at least one axially
spaced pair of receivers.
16. The electromagnetic ranging system of claim 15, wherein the
information handling system is configured to determine a deviation
of a well path based, at least partially, on the at least one
target well parameter.
17. The electromagnetic ranging system of claim 15, wherein the
information handling system is operable to use a weighted
combination of a first target well parameter from the at least one
radially spaced pair of receivers and a second target well
parameter from the at least one axially spaced pair of
receivers.
18. The electromagnetic ranging system of claim 14, wherein the at
least one radially spaced pair of receivers comprise a first pair
of radially spaced receivers positioned on a downhole measurement
tool at a substantially same axial position and a second pair of
radially spaced receivers positioned on the downhole measurement
tool at a different axial position than the first pair, and wherein
the at least one spaced axially pair of receivers shares receivers
with the first pair of radially spaced receives and the second pair
of radially spaced receivers.
19. The electromagnetic ranging system of claim 14, wherein the at
least one radially spaced pair of receivers comprises a pair of
radially spaced receivers that are positioned at a substantially
same axial position, wherein the at least one axially spaced pair
of receivers comprises a receiver axially spaced from the pair of
radially spaced receivers and one or more of the pair of radially
spaced receivers.
20. The electromagnetic ranging system of claim 14, wherein at
least one receiver of the at least one radially spaced pair of
receivers or the axially spaced pair of receivers is oriented in a
direction perpendicular to a longitudinal axis of a downhole
measurement tool.
Description
BACKGROUND
[0001] Wellbores drilled into subterranean formations may enable
recovery of desirable fluids (e.g., hydrocarbons) using a number of
different techniques. Knowing the location of a target wellbore may
be important while drilling a second wellbore. For example, in the
case of a target wellbore that may be blown out, the target
wellbore may need to be intersected precisely by the second (or
relief) wellbore in order to stop the blow out. Another application
may be where a second wellbore may need to be drilled parallel to
the target wellbore, for example, in a steam-assisted gravity
drainage ("SAGD") operation, wherein the second wellbore may be an
injection wellbore while the target wellbore may be a production
wellbore. Yet another application may be where knowledge of the
target wellbore's location may be needed to avoid collision during
drilling of the second wellbore.
[0002] Downhole measurement tools may be employed in subterranean
operations to determine direction and distance between two
wellbores. Downhole measurement tools may use different techniques
to obtain current on a conductive member in the target wellbore.
Approaches may include directly injecting a current into the
conductive member and/or inducing a current on a conductive member
by transmitting electromagnetic fields by coil antennas positioned
in a second wellbore. The induced current in turn may cause the
casing to radiate a secondary electromagnetic field. In another
approach, an electrode type source may be used to induce current on
the conductive member. The gradient of the magnetic field radiated
by the conductive member in addition to the magnetic field itself
may be measured. Using a relationship between the magnetic field
and its gradient, a ranging measurement may be calculated.
Alternatively, an inversion may be used to determine the range, in
which a forward model of the signal that may be received at the
ranging tool may be needed. The inversion process may try to find
the formation and well parameters that would match the forward
model with the measurements made by the tool.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] These drawings illustrate certain aspects of some examples
of the present disclosure, and should not be used to limit or
define the disclosure.
[0004] FIG. 1 is a schematic illustration of an example of an
electromagnetic ranging system in a wellbore.
[0005] FIG. 2 is a schematic illustration an example of a set of
radial receivers arranged in radial directions and an axial
receiver arranged in an axial direction of a downhole measurement
tool.
[0006] FIG. 3A is a schematic illustration of an example of a pair
of receivers.
[0007] FIG. 3B is a schematic illustration of two pairs of
receivers.
[0008] FIG. 3C is a schematic illustration of four pairs of
receivers.
[0009] FIG. 4 is a schematic illustration of an example of a
downhole measurement tool utilizing receivers in a hybrid
radial-axial arrangement.
[0010] FIG. 5 illustrates an example of a work flow of a
measurement process with radial and axial pairs for ranging
calculations.
[0011] FIG. 6 illustrates an example of a distance calculated based
on the gradient method using two data measured by two radially
separated receivers.
[0012] FIGS. 7A-7D illustrates comparison of inversion errors due
to additive random receiver noise.
DETAILED DESCRIPTION
[0013] The present disclosure relates generally to a systems and
methods for electromagnetic ranging. By way of example, this
disclosure may relate to systems and methods for Active
Ranging-While-Drilling (ARWD) for collision avoidance and/or well
interception. This disclosure may relate to systems and methods for
using a set of receivers arranged in radial and axial directions of
a downhole measurement tool to calculate at least one target well
parameter (e.g., the distance and direction) of a target well,
which may be inaccessible. Additionally, the systems and methods
may include ranging from very close to very far distances by using
one single downhole measurement tool. Very close distances may
include about 2 meters to about 60 meters, whereas vary far
distances may include distances larger than 60 meters.
[0014] Determining the position and direction of a conductive pipe
(such as a metallic casing) in a target well accurately and
efficiently may be required in a variety of applications. One of
these applications may be the case of a blow out well where the
target well may be intersected very precisely by a relief well in
order to stop the blowout. Another important application may be
drilling a well parallel to a target well in SAGD applications for
keeping a producer in an effective spot of the injector. Another
application may include the need to detect one or more nearby
target wells during drilling to avoid collision. These nearby
target wells may not be accessible or any information about their
position or structure may not be available. As a result, it may be
of great importance to estimate one or more target well parameters,
such as a relative position of the target wells, which may
typically be characterized with a range, azimuth angle, elevation
angle and target orientation.
[0015] In one method, a source may be located on a bottom hole
assembly ("BHA") to excite a target well and then measure the
magnetic field by the receivers which may also be located on the
same BHA. In another method, coil antenna sources may be used to
induce current on a nearby casing in the target well, and then the
secondary magnetic field created by the induced current may be
detected by receivers (e.g., magnetometer sensors or other coils)
mounted on the BHA.
[0016] ARWD technologies for collision avoidance and/or well
interception may require access to a target well, whether via a
wireline-deployed intervention tool or surface excitation. The
active source may be magnetic, electromagnetic or acoustic, with
corresponding sensors in an adjacent well. However, in many
drilling applications, access to the target well for excitation may
not be possible. Thus, an electromagnetic ranging system capable of
being deployed from a BHA that may measure data to calculate one or
more target well parameters (e.g., a range and direction from the
BHA to at least one target well), may be desired.
[0017] An electromagnetic ranging system may comprise a downhole
measurement tool, which may comprise a transmitter and/or receiver.
Transmission of electromagnetic fields by the transmitter and the
recordation of signals by the receiver, may be controlled by an
information handling system which may be located within a downhole
measurement tool and/or corresponding surface equipment.
[0018] Systems and methods of the present disclosure may be
implemented, at least in part, with an information handling system.
An information handling system may include any instrumentality or
aggregate of instrumentalities operable to compute, classify,
process, estimate, transmit, receive, retrieve, originate, switch,
store, display, manifest, detect, record, reproduce, handle, or
utilize any form of information, intelligence, or data for
business, scientific, control, or other purposes. An information
handling system may include a control unit. For example, an
information handling system may be a personal computer, a network
storage device, or any other suitable device and may vary in size,
shape, performance, functionality, and price. The information
handling system may include random access memory (RAM), one or more
processing resources such as a central processing unit (CPU) or
hardware or software control logic, ROM, and/or other types of
nonvolatile memory. Additional components of the information
handling system may include one or more disk drives, one or more
network ports for communication with external devices as well as
various input and output (I/O) devices, such as a keyboard, a
mouse, and a video display. The information handling system may
also include one or more buses operable to transmit communications
between the various hardware components.
[0019] Alternatively, systems and methods of the present disclosure
may be implemented, at least in part, with non-transitory
computer-readable media. Non-transitory computer-readable media may
include any instrumentality or aggregation of instrumentalities
that may retain data and/or instructions for a period of time.
Non-transitory computer-readable media may include, for example,
storage media such as a direct access storage device (e.g., a hard
disk drive or floppy disk drive), a sequential access storage
device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM,
ROM, electrically erasable programmable read-only memory (EEPROM),
and/or flash memory; as well as communications media such wires,
optical fibers, microwaves, radio waves, and other electromagnetic
and/or optical carriers; and/or any combination of the
foregoing.
[0020] FIG. 1 illustrates an electromagnetic ranging system 102. As
illustrated, a target wellbore 104 may extend from a first wellhead
106 into a subterranean formation 108 from a surface 110.
Generally, target wellbore 104 may include horizontal, vertical,
slanted, curved, and other types of wellbore geometries and
orientations. Target wellbore 104 may be cased or uncased. A
conductive member 112 may be disposed within target wellbore 104
and may comprise a metallic material that may be conductive and
magnetic. By way of example, conductive member 112 may be a casing,
liner, tubing, or other elongated steel tubular disposed in target
wellbore 104. Determining one or more target well parameters (e.g.,
the position and direction of target wellbore 104) accurately and
efficiently may be required in a variety of applications. For
example, target wellbore 104 may be a "blowout" well. Target
wellbore 104 may need to be intersected precisely by a second
wellbore 114 in order to stop the "blowout." Alternatively, it may
be desired to avoid collision with target wellbore 104 in drilling
second wellbore 114 or it may be desired to drill the second
wellbore 114 parallel to the target wellbore 104, for example, in
SAGD applications. In examples, target wellbore 104 may not be
accessible and/or information about the position and structure of
target wellbore 104 may not be available. As will be discussed in
more detail, electromagnetic ranging system 102 may be used for
determining the location of target wellbore 104 with respect to
second wellbore 114.
[0021] With continued reference to FIG. 1, second wellbore 114 may
also extend from a second wellhead 116 that extends into
subterranean formation 108 from surface 110. Generally, second
wellbore 114 may include horizontal, vertical, slanted, curved, and
other types of wellbore geometries and orientations. Additionally,
while target wellbore 104 and second wellbore 114 are illustrated
as being land-based, it should be understood that the present
techniques may also be applicable in offshore applications. Second
wellbore 114 may be cased or uncased. In examples, a conveyance 118
may begin at second wellhead 116 and traverse second wellbore 114.
A drill bit 120 may be attached to a distal end of conveyance 118
and may be driven, for example, either by a downhole motor and/or
via rotation of conveyance 118 from surface 110. Drill bit 120 may
be a part of BHA 122 at distal end of conveyance 118. While not
illustrated, BHA 122 may further comprise one or more of a mud
motor, power module, steering module, telemetry subassembly, and/or
other sensors and instrumentation as will be appreciated by those
of ordinary skill in the art. BHA 122 may be a measurement-while
drilling (MWD) or logging-while-drilling (LWD) system.
[0022] Electromagnetic ranging system 102 may comprise a downhole
measurement tool 124. Downhole measurement tool 124 may be
operatively coupled to conveyance 118 (e.g., wireline, slickline,
coiled tubing, pipe, drill pipe, downhole tractor, or the like)
which may provide electrical connectivity, as well as mechanical
suspension, for downhole measurement tool 124.
[0023] Downhole measurement tool 124 may be a part of BHA 122.
Downhole measurement tool 124 may be used for determining one or
more target well parameters. Additionally, downhole measurement
tool 124 may be connected to and/or controlled by information
handling system 126, which may be disposed on surface 110 and/or on
downhole measurement tool 124. In examples, information handling
system 126 may communicate with downhole measurement tool 124
through a communication line (not illustrated) disposed in (or on)
conveyance 118. In examples, wireless communication may be used to
transmit information back and forth between information handling
system 126 and downhole measurement tool 124. Information handling
system 126 may transmit information to downhole measurement tool
124 and may receive as well as process information recorded by
downhole measurement tool 124. In addition, downhole measurement
tool 124 may include a downhole information handling system 128,
which may also be disposed on BHA 122. Downhole information
handling system 128 may include, a microprocessor or other suitable
circuitry, for receiving and processing signals received by the
downhole measurement tool 124. Downhole information handling system
128 may further include additional components, such as memory,
input/output devices, interfaces, and the like. While not
illustrated, the downhole measurement tool 124 may include one or
more additional components, such as analog-to-digital converter,
filter and amplifier, among others, that may be used to process the
measurements of the downhole measurement tool 124 before they may
be transmitted to surface 110. Alternatively, raw measurements from
downhole measurement tool 124 may be transmitted to surface
110.
[0024] In examples, downhole measurement tool 124 may comprise a
transmitter 130 and a set of radial receivers 132 arranged in
radial directions and an axial receiver 136 arranged in an axial
direction of downhole measurement tool 124. As disclosed herein,
radial receivers 132 and axial receiver 136 may be used to perform
field measurement for electromagnetic ranging. The radial receivers
132 may be separated radially in that the radial receivers 132 may
be spaced perpendicular to the axis of BHA 122. The axial receiver
136 may be spaced axially in that the axial receiver 136 may be
spaced axially (parallel to the axis of BHA 122) from one or more
of the radially receiver 132 or an additional receiver. There may
be a combination of a radially spaced pair or receivers, such as
radial receivers 132, and an axially spaced pair of receivers. The
axially spaced pair of receivers may include axial receiver 136 in
combination with one or more of radial receivers 132 or an
additional receiver.
[0025] Any of a variety of different transmitters 130, radial
receivers 132, and axial receiver 136 for generating and/or
measuring electromagnetic fields may be suitable for use,
including, but not limited to, coil antenna, wire antenna, toroidal
antenna and/or azimuthal button electrodes. Magnetometers may also
be used as the radial receivers 132 and/or the axial receiver 136.
Transmitter 130 may be energized, which may be controlled by
information handling system 126 and/or downhole information
handling system 128, to produce a magnetic field that may be
emitted into subterranean formation 108. The magnetic field may
energize conductive member 112 within target wellbore 104 by
inducing eddy currents in conductive member 112. While FIG. 1 shows
transmitter 130 on downhole measurement tool 124, transmitter 130
may be omitted and conductive member 112 may be energized using
alternative techniques, such as by coupling a current source
directly to conductive member 112 to generate currents. The
currents within conductive member 112 may in turn produce a
secondary magnetic field. This secondary magnetic field may radiate
from target wellbore 104. The radial receivers 132 may be used to
perform a first set of field measurements, The axial receiver 136
may be used to perform a second set of field measurements. Using at
least one of the first set of field measurements or the second set
of field measurements, one or more target well parameters of target
wellbore 104 may be determined. By way of example, the direction
and distance of target wellbore 104 may be determined with respect
to second wellbore 114.
[0026] Any suitable technique may be used for transmitting signals
from downhole measurement tool 124 to surface 110, including, but
not limited to, wired pipe telemetry, mud-pulse telemetry, acoustic
telemetry, and electromagnetic telemetry. While not illustrated,
BHA 122 may include a telemetry subassembly that may transmit
telemetry data to the surface. A transmitter in the telemetry
subassembly may be operable to generate pressure pulses in the
drilling fluid that propagate along the fluid stream to surface
110. At surface 110, pressure transducers (not shown) may convert
the pressure signal into electrical signals for a digitizer 131.
Digitizer 131 may supply a digital form of the telemetry signals to
information handling system 126 via a communication link 134, which
may be a wired or wireless link. The telemetry data may be analyzed
and processed by information handling system 126. For example, the
telemetry data could be processed to determine location of target
wellbore 104. With the location of target wellbore 104, a driller
may control the BHA 122 while drilling second wellbore 114 to
intentionally intersect target wellbore 104, avoid target wellbore
104, and/or drill second wellbore 114 in a path parallel to target
wellbore 104.
[0027] FIG. 2 illustrates a downhole measurement tool 124 that
comprises a radially spaced pair of receivers, namely radial
receivers 132 arranged in radial directions. Radial receivers 132
may have a radial spacing of .DELTA.S. Downhole measurement tool
124 also includes axial receiver 236 arranged in an axial direction
of downhole measurement tool 224 and axially spaced from radial
receivers 132. Axial receiver 136 may form an axially spaced pair
of receivers with one or more of the radial receivers 132 or with
one or more additional receivers. The radial receivers 132 and
axial receiver 136 may be used to calculate the distance and
direction to a conductive inaccessible well, such as, for example,
target wellbore 104. This idea may necessitate a proper arrangement
for transmitter 230, radial receivers 132, and axial receiver 236
and using a controller to switch between proper methods for
distance calculation.
[0028] A cross section of a subterranean formation 108 and the
target wellbore 104 and second wellbore 214 including the
transmitter 230, radial receivers 132, and axial receiver 236 in
the x-z plane is depicted. Transmitter 230 may include a
transmitting tilted coil installed on the downhole measurement tool
224 at a distance dTR.sub.1 from the radial receivers 132 and a
distance dTR.sub.2 from axial receiver 236 to excite current on the
target wellbore 104. The inclination angle .theta. and the distance
D between the target wellbore 104 and the drill bit 120 are also
shown on FIG. 2. The distance between the drill bit 120 and the
closest component (transmitter 230 and radial receivers 132/axial
receiver 236) is also denoted by d.sub.bit.
[0029] Wells may have metallic (such as steel) casings around them
to fortify the well structure and prevent collapsing of the
borehole wall. Since casing may be much more conductive than the
formation around it, a strong coupling of the electric field to the
target wellbore 104 may occur. This coupling of the electric field
may produce a conduction current on the target wellbore 104. This
current may then induce a magnetic field around target wellbore 104
whose magnitude may be detected by magnetic field sensors, such as,
for example, radial receivers 132 and axial receiver 236.
[0030] Analysis of electromagnetic received data at radial
receivers 132 and axial receiver 236 may provide target well
parameters between the target wellbore 104 and the downhole
measurement tool 224. In some systems and methods, an inversion
algorithm based on the laws governing electromagnetic fields may be
used to determine the position of transmitter 230 from radial
receivers 132 and axial receiver 236. This inversion algorithm may
be based on deterministic and/or stochastic numerical optimization
in the form of minimization of a cost function. Cost function may
be formed as the difference between the modeled measurements based
on target well parameters and the downhole measurements. The
distance D, inclination angle .theta., azimuth angle .PHI., and
target orientation {circumflex over (n)} may be found, for example,
if a sufficiently diverse set of field measurements is provided.
For example, two field measurements may be sufficient to determine
the distance D and the inclination angle .theta.. There may be
different configurations in which radial receivers 132, axial
receiver 236, and transmitter 230 may be placed on the downhole
measurement tool 224 to perform the measurement.
[0031] For a radial configuration, radial receivers 132 may be
separated along the radial direction of the downhole measurement
tool 224. Radial receivers 132 may be separated by a fixed distance
.DELTA.S along the radial direction in a single depth. Both of
radial receivers 132 may perform field measurements and one of the
radial receivers 132 may calculate the gradient field to calculate
the distance D to the target wellbore 104.
[0032] A transmitting coil of transmitter 230 may produce an
induced current on the target wellbore 104. This current may then
induce a magnetic field around the target wellbore 104 whose
magnitude may be found via the Biot-Savart law. If the induced
current is constant, Biot-Savart law may reduce to Ampere's law and
the magnetic field at a point may be given by equation (1) where
I.sub.effi is an effective current on the target wellbore 104 and R
is the radial distance from the target wellbore 104 to point r.
H .fwdarw. i ( r ) = I eff 2 .pi. r .phi. ^ ( 1 ) ##EQU00001##
[0033] The gradient of the magnetic field at the same location,
.differential. H .fwdarw. i ( r .fwdarw. ) .differential. r ,
##EQU00002##
is given by equation (2).
.differential. H .fwdarw. i ( r ) .differential. r .apprxeq. I eff
2 .pi. r 2 .phi. ^ ( 2 ) ##EQU00003##
[0034] By taking the ratio of
H .fwdarw. i ( r .fwdarw. ) to .differential. H .fwdarw. i ( r
.fwdarw. ) .differential. r , ##EQU00004##
the radial distance to the target wellbore 104 may be determined as
follows:
R = H .fwdarw. i ( r .fwdarw. ) .differential. H .fwdarw. i ( r
.fwdarw. ) .differential. r ( 3 ) ##EQU00005##
[0035] The current induced on the target wellbore 104 may be
non-uniform, but if the downhole measurement tool 224 is close to
the target wellbore 104 and the separation between radial receivers
132 is small (e.g., about 6 inches), the uniform current assumption
may give accurate results.
[0036] For an axial configuration, sensors such as, for example,
receivers 236 may be separated along the axial direction of the
downhole measurement tool 124. The assumption that the induced
current may be uniform along the target wellbore 104 may not be
precise enough when downhole measurement tool 124 is at far
distances from the target wellbore 104. For far distance ranging
scenarios, more sophisticated inversion algorithms may be used
instead of the gradient technique. To have a successful inversion,
measurements may be as independent as possible and also provide an
accurate signal-level difference between the two measurements to
reduce ambiguity and linear dependency between them. To allow for
this, the sensors may be at a sufficient distance from each other
for an adequate signal gradient. To have a large distance between
the sensors (radial receivers 132, axial receiver 236, etc.), one
may position sensors along the downhole measurement tool 124 axis
and set a desired distance between them. As illustrated, axial
receiver 236 may be positioned at a desired distance from radial
receivers 132. The signal data obtained from the downhole
measurement tool 124 may be used in an inversion step to produce
the target wellbore 104 parameters. In an inversion process, the
measurement data may be matched to the signal data that comes from
the system model. The distance D, inclination angle .theta.,
azimuth angle .PHI. and orientation {circumflex over (n)} may be
found by the inversion process if a sufficiently diverse set of
field measurements is provided. For example, if only D and .theta.
are unknown, two field measurements may be sufficient for
inversion. If .PHI. is an unknown as well; multiple field
measurements at different rotation angles may be used in the
inversion to uniquely compute .PHI.. In case {circumflex over (n)}
vector (target orientation) is unknown, it may be found by using
multiple depth information, multiple transmitter-receiver spacings
or multiple channels with different tilt angles. In a hybrid
radial/axial configuration, a combination of radial and axial pairs
of sensors (e.g., radial receivers 132, axial receivers 236) may be
used in downhole measurement tool 124. The radial pair sensors
(e.g., radial receivers 132) may measure the magnetic field at a
single depth and the data will be processed for distance
calculation for close or parallel ranging and the axial pair
sensors' (e.g., axial receiver 236 and one of radial receivers 132
or another sensor) data may be used for far distance ranging. At
least one first target well parameter may be calculated based, at
least partially, on the first set of field measurements; and at
least one second target well parameter may be calculated based, at
least partially, on a second set of field measurements. The step of
calculating at least one target well parameter may use a weighted
combination of the at least one first target well parameter and the
at least one second target well parameter. Weights for the weighted
combination based on the at least one second target well parameter
may be determined. A threshold based on a distance or relative
angle between the wellbore and the target wellbore 104 may be
determined. The weighted combination may assign a value of 0 or 1
to a first weight for the at least one first target well parameter
and a value of 0 or 1 to a second weight for the at least one
second target well parameter. At least one radially spaced pair of
the receivers comprise a first pair of radially spaced receivers
132 positioned on the downhole measurement tool 124 at the
substantially same axial position and a second pair of radially
spaced receivers 132 positioned on the downhole measurement tool
124 at a different azimuthal position than the first pair. At least
one receiver of the radially spaced pair of the receivers 132 may
be shared with the axially spaced pair of the receivers 136. At
least one receiver of the at least one radially spaced pair of
receivers 132 or the axially spaced pair of receivers 136 is
oriented in a direction perpendicular to a longitudinal axis of the
downhole measurement tool 124. The step of calculating at least one
target well parameter of a target wellbore 104 may comprise
applying an inversion technique to the second field measurements to
provide a first calculated distance and a first calculated
inclination angle to the target wellbore 104. The step of
calculating at least one target well parameter of a target wellbore
104 may further comprise, applying a gradient technique to the
first field measurements to determine a second calculated distance
and a second calculated inclination angle to the target wellbore
104 if the first calculated distance and the first calculated
inclination angle to the target wellbore 104 are less than
respective thresholds. Deviations in path of the wellbore based, at
least in part, on the at least one target wellbore 104 parameter,
correcting a trajectory of a bottom hole assembly trajectory used
in drilling the wellbore based, at least in part, on the determined
deviations; and continuing drilling the wellbore with the BHA 122.
The information handling system may be operable to calculate at
least one target well parameter of a target wellbore 104 from at
least one of first field measurements for the at least one radially
spaced pair of receivers 132 or second field measurements for the
at least one axially spaced pair of receivers 136. The information
handling system may be configured to determine a deviation of a
well path based, at least partially, on the at least one target
well parameter. The information handling system may be operable to
use a weighted combination of a first target well parameter from
the at least one radially spaced pair of receivers 132 and a second
target well parameter from the at least one axially spaced pair of
receivers 136. The at least one radially spaced pair of receivers
may comprise a first pair of radially spaced receivers 132
positioned on the downhole measurement tool 124 at the
substantially same axial position and a second pair of radially
spaced receivers 132 positioned on the downhole measurement tool
124 at a different axial position than the first pair, and wherein
the at least one spaced axially pair of receivers 136 shares
receivers with the first pair and the second pair. The at least one
radially spaced pair of receivers 132 comprises a pair of radially
spaced receivers 136 that are positioned at the substantially same
axial position, wherein the at least one axially spaced pair of
receivers 132 comprises a receiver axially spaced from the pair of
radially spaced receivers 132 and one or more of the pair of
radially spaced receivers 136. The at least one receiver of the at
least one radially spaced pair of receivers 132 or the axially
spaced pair of receivers 136 is oriented in a direction
perpendicular to a longitudinal axis of the downhole measurement
tool 124. The at least one receiver of the at least one radially
spaced pair of receivers 132 or the axially spaced pair of
receivers 136 comprises a coil antenna.
[0037] Referring now to FIG. 3A, radial receivers 132 are shown in
more detail. As illustrated, radial receivers 132 may be separated
along the radial direction of the tool face 300 of downhole
measurement tool 124 with center 302. While drilling, the downhole
measurement tool 124 may rotate and at certain azimuth angles
between radial receivers 132 and the target wellbore 104, the
radial receivers 132 may read identical fields and thereby, the
gradient field calculation may be inaccurate. By way of example,
these blind spots occur when only first pair of radial receivers
132 are used in the downhole measurement tool 124. To avoid the
blind spots, rotate the downhole measurement tool 124 may be
rotated to locate the first pair of radial receivers 132 at the
proper azimuth angles and then perform field measurements or in a
non-rotating scenario, a second pair of second radial receivers 404
may be used with radial receivers 132 at different downhole
measurement tool 124 azimuth angles as illustrated for example in
FIG. 3B, wherein downhole measurement tool 124 may comprise tool
face 300 and center 302. When first pair of radial receivers 132
may be in a blind spot orientation, the second pair of second
radial receivers 304 may not, and may perform the gradient
measurement. By utilizing more radial sensors, the sensitivity and
accuracy of the ranging measurement may be even more improved. FIG.
3C illustrates utilizing 8 sensors (e.g., first radial receivers
132, second radial receivers 304, third radial receivers 306,
fourth radial receivers 308) located around the downhole
measurement tool 124. Downhole measurement tool 124 may comprise
tool face 300 and center 302.
[0038] FIG. 4 illustrates a downhole measurement tool 124 utilizing
sensors in a hybrid radial-axial arrangement. Four sets (sets of
two) of receivers 400, 402, 404 and 406 may be located on the
downhole measurement tool 124 by a distance 408 along the downhole
measurement tool 124 axis. Each set may include a pair of receivers
that may be separated along the radial direction of the downhole
measurement tool 124. The data measured by axially separated
receivers 400, 402, 404 and 406 may be used in an inversion process
to calculate the distance and direction to the target wellbore 104
(shown in FIG. 1). The results may then go to a control unit. If
the distance D and inclination angle .theta. are smaller than
respective thresholds, then the control unit may set the downhole
measurement tool 124 to perform gradient ranging calculations by
using the radial receivers' data. The thresholds for D and .theta.
to switch between axial and radial pairs may be determined by
system modeling or lab measurements. Using both radial and axial
pair configurations may provide a capability for ranging
measurements from close to far distances, and for parallel and
T-intersection ranging.
[0039] FIG. 5 illustrates a work flow of a measurement process with
radial and axial pairs for ranging calculations. The distance D
obtained from gradient measurement may be used to calibrate an
axial measurement apparatus. D is the distance between the drill
bit 120 and the target wellbore 104. When close to the target
wellbore 104, the gradient formula may be accurate. Using the D
value obtained from the gradient formula, the inversion algorithm
of the axial pair(s) may be adjusted such that they give the same D
value. Adjustable inversion parameters may vary (formation
resistivity, inclination angle, initial guesses, etc.).
Periodically calibrated this way at small distances, the axial
pair(s) may perform better at larger distances where they are
actually used. This calibration may improve the inversion accuracy
of the axial setup at larger D values. Box 500 provides exciting
with a transmitter (e.g., transmitter 130 shown in FIG. 1). Field
measurements may be performed by the receivers (e.g., radial
receivers 132, axial receiver 136), as shown in box 502. Box 504
provides that the field measurements by the axial pairs (e.g.,
receivers 236, shown in FIG. 2) may be used in an inversion
calculation to calculate distance and inclination angle to the
target wellbore 104 (shown in FIG. 1). Box 506 provides that if the
calculated distance and inclination angle are smaller than
respective thresholds, then the data measured by the radial pairs
(radial receivers 132, shown in FIG. 2) may be used in a gradient
method to calculate distance and direction to the target wellbore
104. Box 508 may provide determining any deviations in a drilling
well path and correcting BHA trajectory if necessary. Box 510
provides that drilling may continue.
[0040] Features of this disclosure may include transmitters 130
and/or receivers 132 which may comprise coil antennas. There may be
no necessity to have access to a target wellbore 104, thus, this
method may be used for detecting metallic ghost wells in a field
area which there may be no information about possible wells nearby.
For close distance ranging, radially separated sensors may be used,
and a gradient technique may provide for a fast and precise method
to calculate distance and direction to a target wellbore 104. For
far distance ranging, axially separated sensors may be used, and an
inversion algorithm may be applied to calculate distance and
direction to the target wellbore 104. Inversion may not be as fast
and precise as the gradient method for close distance ranging, but
it may provide a possibility of ranging for far distances in which
a gradient method may not be applied. The disclosed techniques may
be utilized in parallel to T-intersection scenarios. During
drilling, the disclosed techniques may be utilized in logging while
drilling ("LWD") ranging in SAGD oilfield operations and well
interception. After drilling, the disclosed techniques may have
direct relevance to production and reservoir monitoring.
[0041] A method for electromagnetic ranging of a target wellbore
may comprise disposing a downhole measurement tool into a wellbore,
wherein the downhole measurement tool may comprise receivers
comprising at least one radially spaced pair of the receivers and
at least one axially spaced pair of the receivers; performing field
measurements with the receivers, where a first set of field
measurements are from at least one radially spaced pair of the
receivers, and a second set of field measurements are from at least
one axially spaced pair of the receivers; and calculating at least
one target well parameter of a target well from at least one of the
first set of field measurements and the second set of field
measurements. The method may further comprise calculating at least
one first target well parameter based, at least partially, on the
first set of field measurements; and calculating at least one
second target well parameter based, at least partially, on the
second set of field measurements. The step of calculating at least
one target well parameter may use a weighted combination of the at
least one first target well parameter and the at least one second
target well parameter. The method may further comprise determining
weights for the weighted combination based on the at least one
second target well parameter. The method may further comprise
determining a threshold based on a distance or relative angle
between the wellbore and the target well. The weighted combination
may assign a value of 0 or 1 to a first weight for the at least one
first target well parameter and a value of 0 or 1 to a second
weight for the at least one second target well parameter. The at
least one radially spaced pair of the receivers may comprise a
first pair of radially spaced receivers positioned on the downhole
measurement tool at the substantially same axial position and a
second pair of radially spaced receivers positioned on the downhole
measurement tool at a different azimuthal position than the first
pair. The at least one receiver of the radially spaced pair of the
receivers may be shared with the axially spaced pair of the
receivers. At least one receiver of the at least one radially
spaced pair or the axially spaced pair may be oriented in a
direction perpendicular to a longitudinal axis of the downhole
measurement tool. The step of calculating at least one target well
parameter of a target well may comprise applying an inversion
technique to the second field measurements to provide a first
calculated distance and a first calculated inclination angle to the
target well. The step of calculating at least one target well
parameter of a target well may further comprise, applying a
gradient technique to the first field measurements to determine a
second calculated distance and a second calculated inclination
angle to the target well if the first calculated distance and the
first calculated inclination angle to the target well are less than
respective thresholds. The method may further comprise deviations
in path of the wellbore based, at least in part, on the at least
one target well parameter, correcting a trajectory of a BHA
trajectory used in drilling the wellbore based, at least in part,
on the determined deviations; and continuing drilling the wellbore
with the BHA.
[0042] An electromagnetic ranging system may comprise at least one
radially spaced pair of receivers; at least one axially spaced pair
of receivers; and an information handling system, wherein the
information handling system is configured to switch between the at
least one radially spaced pair of receivers and the at least one
axially spaced pair of receivers. The information handling system
may be operable to calculate at least one target well parameter of
a target well from at least one of first field measurements for the
at least one radially spaced pair of receivers or second field
measurements for the at least one axially spaced pair of receivers.
The information handling system may be configured to determine a
deviation of a well path based, at least partially, on the at least
one target well parameter. The information handling system may be
operable to use a weighted combination of a first target well
parameter from the at least one radially spaced pair of receivers
and a second target well parameter from the at least one axially
spaced pair of receivers. The at least one radially spaced pair of
receivers may comprise a first pair of radially spaced receivers
positioned on the downhole measurement tool at the substantially
same axial position and a second pair of radially spaced receivers
that may be positioned on a downhole measurement tool at a
different axial position than the first pair, and wherein the at
least one spaced axially pair of receivers may share receivers with
the first pair and the second pair. The at least one radially
spaced pair of receivers may comprise a pair of radially spaced
receivers that may be positioned at the substantially same axial
position, wherein the at least one axially spaced pair of receivers
may comprise a receiver axially spaced from the pair of radially
spaced receivers and one or more of the pair of radially spaced
receivers. At least one receiver of the at least one radially
spaced pair or the axially spaced pair may be oriented in a
direction perpendicular to a longitudinal axis of a downhole
measurement tool. At least one receiver of the at least one
radially spaced pair or the axially spaced pair may comprise a coil
antenna.
[0043] To facilitate a better understanding of the present
disclosure, the following examples of certain aspects of some of
the systems, methods and cement compositions are given. In no way
should the following examples be read to limit, or define, the
entire scope of the disclosure.
Example 1
[0044] A modelled example of electromagnetic ranging with the
gradient method for a radial configuration will now be described
with respect to FIG. 2. Target wellbore 104 may be a thin hollow
metal with the following properties: .sigma.=10.sup.6 S/m,
.epsilon..sub.r=1, .mu..sub.r=60, OD=8'', and inner diameter
("ID")=7''. The length of the target wellbore 104 may be assumed
2000 m. Transmitter 230 may be assumed to be located around the
mid-point of the target wellbore 104 and in the form of a tilted
coil with a tilt angle of 45.degree.. The drill bit 120 may be
located at a distance D from the target wellbore 104 as shown in
FIG. 2. The transmitter 230 may have a coil diameter of 6.75'' and
may have N=120 turns. The transmitter 230 may be carrying current
I=1A at frequency of 10 Hz. The transmitters 230 or receivers
(e.g., radial receivers 132, axial receiver 236), whichever is
closer to the drill bit 120), may be at a 10 m distance (d.sub.bit)
from the drill bit 120. The subterranean formation 108 may be
assumed to be homogeneous with resistivity (R.sub.f) of 10
.OMEGA.m, wherein .epsilon..sub.fr=.mu..sub.fr=1. The radial
receivers 132 may be located from transmitters 130 at a distance
dTR.sub.1 100 ft with a radial separation .DELTA.S of 6.75'' along
the radial direction of the downhole measurement tool 224.
[0045] FIG. 6 illustrates the calculated distance D to target
wellbore 104 using the gradient method from field measurements of
radial receivers 132 for this modelled example. As illustrated, the
gradient method using radially spaced pairs may provide an accurate
distance calculation for near distances. The gradient formula may
also be more precise for smaller inclination angles (e.g., about
0.degree. to about 30.degree.), as the 60.degree. inclination angle
was the most inaccurate, indicating that the performance may
degrade by going to a T-intersection. The accuracy of the constant
current assumption may also degrade at higher operating
frequencies. So, for high frequency operation, one may need to be
in a close range to the target wellbore 104 (shown on FIG. 2), to
be still able to use the gradient calculation.
Example 2
[0046] Another specific example of electromagnetic ranging with
inversion will now be described with respect to FIG. 2. One
consideration in the performance of an inversion algorithm may be
its robustness against additive noise. Gaussian-distributed
additive noise may be assumed to be present at axial receivers 136.
It is assumed that this noise is zero-mean with standard deviation
.sigma..sub.n is 5 nV. For this example, distance D and inclination
angle .theta. are unknown and so two measurements may be needed for
inversion. It may be assumed that the axially spaced pair may
experience independent noise samples from the same distribution.
The axially spaced pair may include axial receiver 136 and one of
radial receivers 132. A Monte-Carlo analysis may be performed
whereby 100 independent random noise pairs may be added to the
axially spaced pair and the values for distance D/inclination
angles .theta. computed via the inversion algorithm. For the sake
of comparison, two sensor pairs at f=10 kHz (R.sub.f=10 .OMEGA.m)
have been considered: 1) a radially spaced pair comprising radial
receivers 132 with a radial separation .DELTA.S of 6.75'') and a
dTR.sub.1 of 37' from the transmitter 230; 2) the axially spaced
pair with a dTR.sub.1 of 37' and a dTR.sub.2 of 91'. FIGS. 7a to 7d
provide the modelled results for this example. (7A, 7C):
Axially-separated coils at dTR1=37' and dTR2=91', (7B, 7D):
Radially separated coils at dTR1=37' (.DELTA.s=6.75''). As
illustrated, the superiority of the axially spaced pair may be
evident for far distances. The radially spaced pair may offer
acceptable error performance only at range of inclination angles
.theta. from 0.degree. to 10.degree.. This may be due to the fact
that the radial receivers 132 in the radially spaced pair may
register almost the same signal close to a T-intersection.
[0047] The preceding description provides various examples of the
systems and methods of use disclosed herein which may contain
different method steps and alternative combinations of components.
It should be understood that, although individual examples may be
discussed herein, the present disclosure covers all combinations of
the disclosed examples, including, the different component
combinations, method step combinations, and properties of the
system. It should be understood that the compositions and methods
are described in terms of "comprising," "containing," or
"including" various components or steps, the compositions and
methods can also "consist essentially of" or "consist of" the
various components and steps. Moreover, the indefinite articles "a"
or "an," as used in the claims, are defined herein to mean one or
more than one of the element that it introduces.
[0048] For the sake of brevity, only certain ranges are explicitly
disclosed herein. However, ranges from any lower limit may be
combined with any upper limit to recite a range not explicitly
recited, as well as, ranges from any lower limit may be combined
with any other lower limit to recite a range not explicitly
recited, in the same way, ranges from any upper limit may be
combined with any other upper limit to recite a range not
explicitly recited. Additionally, whenever a numerical range with a
lower limit and an upper limit is disclosed, any number and any
included range falling within the range are specifically disclosed.
In particular, every range of values (of the form, "from about a to
about b," or, equivalently, "from approximately a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be
understood to set forth every number and range encompassed within
the broader range of values even if not explicitly recited. Thus,
every point or individual value may serve as its own lower or upper
limit combined with any other point or individual value or any
other lower or upper limit, to recite a range not explicitly
recited.
[0049] Therefore, the present examples are well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular examples disclosed above are
illustrative only, and may be modified and practiced in different
but equivalent manners apparent to those skilled in the art having
the benefit of the teachings herein. Although individual examples
are discussed, the disclosure covers all combinations of all of the
examples. Furthermore, no limitations are intended to the details
of construction or design herein shown, other than as described in
the claims below. Also, the terms in the claims have their plain,
ordinary meaning unless otherwise explicitly and clearly defined by
the patentee. It is therefore evident that the particular
illustrative examples disclosed above may be altered or modified
and all such variations are considered within the scope and spirit
of those examples. If there is any conflict in the usages of a word
or term in this specification and one or more patent(s) or other
documents that may be incorporated herein by reference, the
definitions that are consistent with this specification should be
adopted.
* * * * *